Polymer injectivity is a critical parameter for implementation of polymer flood projects. An improved understanding of polymer injectivity is important in order to facilitate an increase in polymer EOR implementation. Typically, injectivity studies are performed using linear core floods. Here we demonstrate that polymer flow in radial and linear models may be significantly different and discuss the concept in theoretical and experimental terms. Linear core floods using partially hydrolyzed polyacrylamides (HPAM) were performed at various rates to determine in-situ viscosity and polymer injectivity. Radial polymer floods were performed on Bentheimer discs (30 cm diameter, 2-3 cm thickness) with pressure taps distributed between a central injector and the perimeter production well. The in-situ rheological data are also compared to bulk rheology. The experimental set up allowed a detailed analysis of pressure changes from well injection to production line in the radial models and using internal pressure taps in linear cores. Linear core floods show degradation of polymer at high flow rates and a severe degree of shear thickening leading to presumably high injection pressures. This is in agreement with current literature. However, the radial injectivity experiments show a significant reduction in differential pressure compared to the linear core floods. Onset of shear thickening occurs at significantly higher flow velocities than for linear core floods. These data confirm that polymer flow is significantly different in linear and radial flow. This is partly explained by the fact that linear floods are being performed at steady state conditions, while radial injections go through transient (unsteady state) and semi-transient pressure regimes. History matching of polymer injectivity was performed for radial injection experiments. Differences in polymer injectivity are discussed in the framework of theoretical and experimental considerations. The results may have impact on evaluation of polymer flood projects as polymer injectivity is a key risk factor for implementation.
Viscous fingering in porous media occurs when the (miscible or immiscible) displacing fluid has a lower viscosity than the displaced fluid. For example, immiscible fingering is observed in experiments where water displaces a much more viscous oil. Modelling the observed fingering patterns in immiscible viscous fingering has proven to be very challenging, which has often been identified as being due to numerical issues. However, in a recent paper (Sorbie et al. in Transp. Porous Media 133:331–359, 2020) suggested that the modelling issues are more closely related to the physics and formulation of the problem. They proposed an approach based on the fractional flow curve, $${f}_{w}^{*}$$ f w ∗ , as the principal input, and then derived relative permeabilities which give the maximum total mobility. Sorbie et al. were then able to produce complex, well-resolves immiscible finger patterns using elementary numerical methods. In this paper, this new approach to modelling immiscible viscous fingering is tested by performing direct numerical simulations of previously published experimental water/oil displacements in 2D sandstone porous media. Experiments were modelled at adverse viscosity ratios ($${\mu }_{o}/{\mu }_{w}$$ μ o / μ w ), with oil viscosities ranging from μo = 412 to 7000 cP, i.e. for a viscosity ratio range, ($${\mu }_{o}/{\mu }_{w}$$ μ o / μ w ) $$\sim$$ ∼ 400–7000. These experiments have extensive production data as well as in situ 2D immiscible fingering images, measured by X-ray scanning. In all cases, very good quantitative agreement between experiment and modelling results is found, providing a strong validation of the new modelling approach. The underlying parameters used in the modelling of these unstable immiscible floods, the $${f}_{w}^{*}$$ f w ∗ functions, show very consistent and understandable variation with the viscosity ratio, ($${\mu }_{o}/{\mu }_{w}$$ μ o / μ w ).
Water channels are formed in highly permeable thief zones or in situations with a strong adverse mobility ratio, such as waterflood in heavy oil reservoirs. This paper discusses the effect of tertiary polymer injection on oil mobilization in already established water channels generated by viscous unstable flow in apparent homogeneous rock material. Polymers may accelerate oil production by moving oil into water channels, known as crossflow. The conditions for crossflow to occur are discussed and quantified by key parameters for maximizing crossflow. Crossflow in layered rock with permeability contrast has been studied extensively. We have also studied permeability contrast in conventional thief zones for comparison. Recently published experimental studies, including in situ saturation maps, have proven acceleration of heavy oil production by injection of polymer in rather homogeneous sandstones. The simulation study involves computation of saturation-induced crossflow, in particular with respect to wettability, relative permeability hysteresis, capillary pressure, oil viscosity, mobility ratio, and polymer viscosity. To have a realistic representation of channeling, the water channels are constructed from waterflooding saturation data at adverse mobility. Saturation-induced crossflow into water channels at homogeneous permeability is found to be strongly affected by wettability, viscosity ratio (oil/water), and width of water channels.
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